1. Field of Invention
The present disclosure relates to pumping systems submersible in well bore fluids. More specifically, the present disclosure concerns a pumping system having surfactant injected into the fluid being pumped.
2. Description of Prior Art
Centrifugal pumps have been used for pumping well fluids for many years. Centrifugal pumps are designed to handle fluids that are essentially all liquid. Free gas frequently gets entrained within well fluids that are required to be pumped. The free gas within the well fluids can cause trouble in centrifugal pumps. As long as the gas remains entrained within the fluid solution, then the pump behaves normally as if pumping a fluid that has a low density. However, the gas frequently separates from the liquids.
The performance of a centrifugal pump is considerably affected by the gas due to the separation of the liquid and gas phases within the fluid stream. Such problems include a reduction in the pump head, capacity, and efficiency of the pump as a result of the increased gas content within the well fluid. The pump starts producing lower than normal head as the gas-to-liquid ratio increases beyond a certain critical value, which is typically about 10-15% by volume. When the gas content gets too high, the gas blocks all fluid flow within the pump, which causes the pump to become “gas locked.” Separation of the liquid and gas in the pump stage causes slipping between the liquid and gas phase which causes the pump to experience lower than normal head. Submersible pumps are generally selected by assuming that there is no slippage between the two phases or by correcting stage performance based upon actual field test data and past experience.
Many of the problems associated with two phase flow in centrifugal pumps would be eliminated if the wells could be produced with a submergence pressure above the bubble point pressure to keep any entrained gas in the solution at the pump. However, this is typically not possible. To help alleviate the problem, gases are usually separated from the other fluids prior to the pump intake to achieve maximum system efficiency, typically by installing a gas separator upstream of the pump. Problems still exist with using a separator upstream of a pump since it is necessary to determine the effect of the gas on the fluid volume in order to select the proper pump and separator. Many times, gas separators are not capable of removing enough gas to overcome the inherent limitations in centrifugal pumps.
A typical centrifugal pump impeller designed for gas containing liquids consists of a set of one-piece rotating vanes, situated between two disk type shrouds with a balance hole that extends into each of the flow passage channels formed by the shrouds and two vanes adjacent to each other. The size of the balance holes vary between pump designs. Deviations from the typical pump configurations have been attempted in an effort to minimize the detrimental effects of gaseous fluids on centrifugal pumps. However, even using these design changes in the impellers of the centrifugal pumps is not enough. There are still problems with pump efficiency, capacity, head, and gas lock in wells producing well fluids with high gas content.
Foaming agents may be added to well fluid to overcome fluid production difficulties associated with gas in the fluid. The vertical flow of fluid from a well depends on the well bottom fluid pressure and the fluid gradient. Oil well flow may start when the wellbore bottom pressure exceeds the static head of the fluid. Continued flow or gushing, may occur because the gas expansion in the upward flowing fluid lightens the fluid column. In some situations, the gas expansion phenomenon is sufficient to lift the fluid even in oil wells having a reduced flow. Injecting a foaming agent to a wellbore fluid can create and maintain a low gradient fluid. The foaming agent plus liquid and gas, combined with the inherent turbulence in fluid flow, forms a low gradient mix as the fluid flows upward in the tubing.